Oil and gas wells are typically constructed with a string of pipe, known as casing or tubing, in the well bore and concrete around the outside of the casing to isolate the various formations that are penetrated by the well. At the strata or formations where hydrocarbons are anticipated, the well operator perforates the casing to allow for the flow of oil and/or gas into the casing and to the surface.
At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons with stimulation by acid treatment or hydraulic fracturing of the hydrocarbon-producing formations surrounding the well. In a hydraulic fracturing operation, a fluid such as water which contains particulate matter such as sand, is pumped down from the surface into the casing and out through the perforations into the surrounding target formation. The combination of the fluid rate and pressure initiate cracks or fractures in the rock. The particulates lodge into these fractures in the target formation and serve to hold the cracks open. The increased openings thus increase the permeability of the formation and increase the ability of the hydrocarbons to flow from the formation into the well casing after the fracture treatment is completed.
Within a given formation, the fracture gradient is the pressure or force needed to initiate a fracture in the formation by way of pumping a fluid at any rate. The fracture gradient for a formation may be calculated from the instantaneous shut-in pressure (“ISIP”). The ISIP is an instant pressure reading obtained when the operator pumps a fluid at a desired rate then abruptly decreases the pump rate to zero and instantaneously reads the pump pressure. The pressure reading at zero pump rate is the ISIP.
In relatively thin formations that are fairly homogeneous, the above referenced standard fracturing technique will normally produce a fracture or fractures throughout the depth of the formation. However, when an operator attempts to fracture a large formation having multiple zones of varying stresses and different fracture gradients in a normal fracture treatment, the fracture fluid tends to dissipate only into those portions of the formation having the lowest fracture gradient and the lowest stress gradient. Thus, the fracture treatment may only be effective in a small portion of the overall target formation.
Therefore, operators and service companies in the oil and gas industry have the common problem of finding an economical, innovative, simple solution to stimulate an entire lateral section of a horizontal well effectively. This problem exists for both cemented and un-cemented lateral sections of an oil or gas well. Referring to FIG. 1, a horizontal well is shown with steel casing 100 inserted through a target formation. The steel casing 100 may or may nor have cement between the outside of the casing 100 and the formation. The horizontal well 100 has a lateral section 102 with a heel 104 and toe 106. At certain points in the casing, perforations 108 are formed through the casing using techniques known in the art. These perforations 108 are formed near targeted production zones of the formation, and the perforations 108 allow the hydrocarbons to pass from the formation into the casing 100.
Various analysis techniques, such as radioactive tracer logs, micro-seismic monitoring, and tilt-meter technology, have revealed that the lateral's “mid-section”, whether the lateral is 500-ft. in length or longer, is typically “under-stimulated.” The various analysis techniques show a trend that up to about 80% of a treatment fluid is only pumped into the rock or formations located at the heel 104 and toe 106 of the lateral section 102. Thus, one problem with treating a long lateral of a horizontal well is that the treatment fluid tends to go in only certain portions of the rock having the lowest stress gradients, leaving much of the production un-stimulated. This is currently seen in horizontal wells in the Barnett Shale. In other words, the majority of a stimulation treatment, such as a fracture treatment on the lateral well, will not reach the productive rock 110 near the middle of the lateral section 102. This phenomenon can economically hurt operators, who expend considerable amounts of time and money to drill and stimulate the horizontal well. Namely, the operators are unable to tap amounts of production and reserves left in the under-stimulated formations.
This phenomenon (i.e., the “80% Heel-Toe” phenomenon) occurs because most horizontal wells are drilled through rock formations that have varying stress gradients and varying rock properties (such as permeability and porosity). The stress gradient of a rock corresponds to how easily the rock can be fractured and how readily the rock can receive a treatment fluid to stimulate the rock. In general, stimulation fluid flows to the path of least resistance (e.g., the rock formation with the lowest stress gradient). For example, if a well has perforations near rock formations with multiple stress gradients, the stimulation fluid flows into the rock formations having the lowest stress gradient. The rock formations having the higher stress gradient may only take part of the stimulation fluid or may not take any stimulation fluid at all.
In one prior art solution, operators and service companies overcome this “80% Heel-Toe” phenomenon by mechanically dividing a horizontal well's lateral into stages. For example, operators set mechanical bridge plugs in the well to shorten the length of the lateral section and to divide the treatment with stimulation fluid into steps or stages. Mechanically dividing the lateral section with bridge plugs allows the operators to better stimulate all the rock formations. However, dividing a well into stages with mechanical bridge plugs costs the operator more time (up to twice as long) and much more money (about 75% more). In addition, the use of mechanical bridge plugs also increases the potential for mechanical failures.
Some horizontal wells contain lateral sections that have the steel casing cemented into the rock (i.e., the cement is positioned between the outside of the steel casing and the rock). For a cemented lateral, the “80% Heel-Toe” phenomenon during stimulation treatment can be overcome by using ball sealers (rubber coated or degradable) as diverting agents. In this prior art solution, the ball sealers are pumped into the casing and become seated in perforations of the casing taking fluid. As has been shown, the ball sealers typically become seated in perforations located at the heel 104 and toe 106 or near rock formations having the lowest stress gradients. When seated, the ball sealers divert the stimulation fluid and change the fluid's path. The treatment fluid is then forced to the perforations with the rock of higher stress gradients or in the mid-section of the lateral. This method of treating cemented laterals has proven effective in many areas by eliminating the costly need of multiple mechanical stages.
A limitation of ball sealers is that they are successful in diversion only when the casing of a well is surrounded by cement with respect to the rock. Namely, other horizontal wells contain steel casing that is un-cemented with the rock. If ball sealers are used to divert the fluid, the treatment fluid can still travel its original path to the rock formations with the lowest stress gradient behind the casing because there is no cement to change the fluid's course when the perforations are sealed closed with ball sealers. Thus, in cases where a well is not cemented in the “target” rock, ball sealers are ineffective and a waste of money and time.
It is known in the art to pump a diverting agent, such as sand plugs into wells. The diverting agent diverts the treatment fluid behind the casing in the formation. For example, one option is to pump sand plugs in with a treatment fluid. These sand plugs consist of 100-mesh grains or other small sizes. This practice can also create diversion in the rock outside the casing. However, in a naturally fractured formation, the sand plugs can permanently plug and ultimately damage the conductivity and productivity of a well. The desire is to “temporarily” create a diversion in a treatment fluid without damaging the formation, conductivity, future production, or reserves.
One problem occurring in most fracturing operations is fluid loss from a target formation. A producing formation generally includes horizontal, undulating layers, which can range from several feet to several hundred feet thick. As a fracturing operation proceeds on a vertical well, the fractures can propagate vertically outside of the target zone, which causes fracturing fluid to move into a non-producing areas of the formation that are located above and/or below the producing area of the formation. Total fluid loss is defined as the amount of fracturing fluid lost to the total area of exposed formation of the created fracture and is known in the industry. Fluid loss is preferably controlled; otherwise, the fracture width will not be sufficient to allow proppants to enter the fracture and keep it propped open.
Therefore, additional materials are placed in the fracturing fluid to limit fluid loss. These materials are termed “fluid-loss additives” and are known in the industry. The fluid loss additives are used to prevent a fracturing fluid from prematurely leaking off into the formation by bridging over pores, fissures, etc. The fluid loss additives are typically pumped in concentrations ranging from about 5 to 50-pounds of agent per 1000-gallons of treatment fluid. This translates to about 0.005 to 0.05-pounds of agent per gallon of treatment fluid. Fluid loss additives can be both permanent and degradable. After a stimulation treatment, fluid loss additives either go back into solution, require an additional chemical to breakdown the additive, or can degrade naturally with temperature, if designed properly.
Thus, the oil and gas industry is constantly seeking a solution that would effectively treat an entire lateral section in one stage in as little time as possible, such as one day. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.